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Sour corrosion and iron sulphide scale deposition are two common flow assurance issues encountered in oilfields. Sour oil wells typically produce crude along with produced water and a significant amount of acidic gases such as carbon dioxide and hydrogen sulfide. The high pressure and temperature conditions under the downhole tend to cause severe corrosion damage including metal loss and pitting, along with iron sulphide scale deposition. Iron sulfide deposition in sour wells is a corrosion induced scale problem. It potentially causes production decline, restricted well intervention, well shutdown, or even severe consequences towards to the abandoned wells.
A downhole corrosion and scale monitoring (DCSM) tool was developed and applied in sour oil wells to monitor the corrosion and scale formation under real downhole flow conditions. The cylindrical test coupon was made of T-95 carbon steel, which was identical to the metallurgy of the downhole completion tubing. The corrosion and scale deposited on the surface of the cylindrical test coupon effectively simulated the corrosion and scale deposited on the surface of downhole completion tubing.
The DCSM was installed at a desired depth in the downhole and retrieved after three months. The retrieved coupons were characterized thoroughly to assess the corrosion and scaling mechanisms using scanning electron microscopy (SEM), energy-dispersive X-ray spectroscopy (EDS) analyses, X-ray diffraction (XRD) and surface profilometer. The results showed that a thin layer (~300 micron in thickness) of deposit, mainly composed of pyrrhotite, was formed on the surface of the T-95 coupon. However, an overall weight loss (1.3194 g) due to the combined effects of the iron sulphide deposition (weight gain) and abrasion/corrosion of the outer layer from the surface (weight loss) was observed. After removing the scale deposition, both general corrosion and under-deposit pitting corrosion were detected by the surface profile scan on the T-95 coupon, where the under-deposit pitting corrosion was considered to be the major concern.
This is Part I of a two-part series intended to provide background and a rational justification or supporting rationale for requirements leading to the development and publication of NACE(1) MR 0175 and ISO(2) 15156. Part I focuses on some of the metallurgical and processing requirements; specifically, Rockwell C 22 scale (HRC) limit, the various acceptable heat treatments and the 1wt% Ni limit for carbon and low alloy steels to minimize the threat of sulfide stress cracking (SSC) in H2S containing environments. Part II describes the testing and rationale behind the use of accelerated laboratory test procedures and their development to differentiate metallurgical behavior in sour environments.
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TOL corrosion is reported to occur in large diameter wet gas pipeline in stratified flow conditionsdue to low fluid velocities1. With increasing distance from the inlet, the wet gas pipeline becomescooler as it loses heat to the environment. Such cooling causes water, hydrocarbon, and otherhigh vapor pressure species to condense on the pipe wall. The upper part of the pipe willconstantly be supplied with freshly condensed water while the less corrosive water saturatedwith corrosion products will be drained along the pipe wall to the bottom of the line.
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